System and method for borehole communication

ABSTRACT

A method and an apparatus for communicating between a tool and a surface of a subterranean formation including a signal generator configured to send a signal through the formation, a relay in communication with the generator, and a receiver in communication with the relay. A method and an apparatus for communicating between a tool and a surface of a subterranean formation including sending a signal from a generator configured to send a signal through a formation, receiving the signal at a relay, sending a second signal from the relay, and receiving the second signal at a receiver.

BACKGROUND

1. Technical Field

This invention relates to wellbore communication systems and particularly to systems and methods for generating and transmitting data signals between the surface of the earth and the bottom hole assembly while drilling a borehole.

2. Background

Wells are generally drilled into the ground to recover natural deposits of hydrocarbons and other desirable materials trapped in geological formations in the Earth's crust. A well is typically drilled using a drill bit attached to the lower end of a drill string. The well is drilled so that it penetrates the subsurface formations containing the trapped materials and the materials can be recovered.

At the bottom end of the drill string is a “bottom hole assembly” (“BHA”). The BHA includes the drill bit along with sensors, control mechanisms, and the required circuitry. A typical BHA includes sensors that measure various properties of the formation and of the fluid that is contained in the formation. A BHA may also include sensors that measure the BHA's orientation and position.

The drilling operations may be controlled by an operator at the surface or operators at a remote operations support center. The drill string is rotated at a desired rate by a rotary table, or top drive, at the surface, and the operator controls the weight-on-bit and other operating parameters of the drilling process.

Another aspect of drilling and well control relates to the drilling fluid, called “mud.” The mud is a fluid that is pumped from the surface to the drill bit by way of the drill string. The mud serves to cool and lubricate the drill bit, and it carries the drill cuttings back to the surface. The density of the mud is carefully controlled to maintain the hydrostatic pressure in the borehole at desired levels.

In order for the operator to be aware of the measurements made by the sensors in the BHA, and for the operator to be able to control the direction of the drill bit, communication between the operator at the surface and the BHA are necessary. A “downlink” is a communication from the surface to the BHA. Based on the data collected by the sensors in the BHA, an operator may desire to send data or command to the BHA. A common command is an instruction for the BHA to change the direction of drilling.

Likewise, an “uplink” is a communication from the BHA to the surface. An uplink is typically a transmission of the data collected by the sensors in the BHA. For example, it is often important for an operator to know the BHA orientation. Thus, the orientation data collected by sensors in the BHA is often transmitted to the surface. Uplink communications are also used to confirm that a downlink command was correctly understood.

One common method of communication is called “mud pulse telemetry.” Mud pulse telemetry is a method of sending signals, either downlinks or uplinks, by creating pressure and/or flow rate pulses in the mud. These pulses may be detected by sensors at the receiving location. For example, in a downlink operation, a change in the pressure or the flow rate of the mud being pumped down the drill string may be detected by a sensor in the BHA. The pattern of the pulses, such as the frequency, the phase and the amplitude, may be detected by the sensors and interpreted so that the command may be understood by the BHA.

Mud pulse telemetry systems are typically classified as one of two species depending upon the type of pressure pulse generator used, although “hybrid” systems have been disclosed. The first species uses a valving “poppet” system to generate a series of either positive or negative, and essentially discrete, pressure pulses which are digital representations of transmitted data. The second species, an example of which is disclosed in U.S. Pat. No. 3,309,656, comprises a rotary valve or “mud siren” pressure pulse generator which repeatedly interrupts the flow of the drilling fluid, and thus causes varying pressure waves to be generated in the drilling fluid at a carrier frequency that is proportional to the rate of interruption. Downhole sensor response data is transmitted to the surface of the earth by modulating the acoustic carrier frequency. A related design is that of the oscillating valve, as disclosed in U.S. Pat. No. 6,626,253, wherein the rotor oscillates relative to the stator, changing directions every 180 degrees, repeatedly interrupting the flow of the drilling fluid and causing varying pressure waves to be generated.

With reference to FIG. 1, a drilling rig 10 includes a drive mechanism 12 to provide a driving torque to a drill string 14. The lower end of the drill string 14 extends into a wellbore 30 and carries a drill bit 16 to drill an underground formation 18. During drilling operations, drilling mud 20 is drawn from a mud pit 22 on a surface 29 via one or more pumps 24 (e.g., reciprocating pumps). The drilling mud 20 is circulated through a mud line 26 down through the drill string 14, through the drill bit 16, and back to the surface 29 via an annulus 28 between the drill string 14 and the wall of the wellbore 30. Upon reaching the surface 29, the drilling mud 20 is discharged through a line 32 into the mud pit 22 so that rock and/or other well debris carried in the mud can settle to the bottom of the mud pit 22 before the drilling mud 20 is recirculated.

Referring now to FIG. 1, one known wellbore telemetry system 100 is depicted including a downhole measurement while drilling (MWD) tool 34 is incorporated in the drill string 14 near the drill bit 16 for the acquisition and transmission of downhole data or information. The MWD tool 34 includes an electronic sensor package 36 and a mudflow wellbore telemetry device 38. The mudflow telemetry device 38 can selectively block the passage of the mud 20 through the drill string 14 to cause pressure changes in the mud line 26. In other words, the wellbore telemetry device 38 can be used to modulate the pressure in the mud 20 to transmit data from the sensor package 36 to the surface 29. Modulated changes in pressure are detected by a pressure transducer 40 and a pump piston sensor 42, both of which are coupled to a surface system processor (not shown). The surface system processor interprets the modulated changes in pressure to reconstruct the data collected and sent by the sensor package 36. The modulation and demodulation of a pressure wave are described in detail in commonly assigned U.S. Pat. No. 5,375,098, which is incorporated by reference herein in its entirety.

The surface system processor may be implemented using any desired combination of hardware and/or software. For example, a personal computer platform, workstation platform, etc. may store on a computer readable medium (e.g., a magnetic or optical hard disk, random access memory, etc.) and execute one or more software routines, programs, machine readable code or instructions, etc. to perform the operations described herein. Additionally or alternatively, the surface system processor may use dedicated hardware or logic such as, for example, application specific integrated circuits, configured programmable logic controllers, discrete logic, analog circuitry, passive electrical components, etc. to perform the functions or operations described herein.

Still further, while the surface system processor can be positioned relatively proximate to the drilling rig (i.e., substantially co-located with the drilling rig), some part of or the entire surface system processor may alternatively be located relatively remotely from the rig. For example, the surface system processor may be operationally and/or communicatively coupled to the wellbore telemetry component 18 via any combination of one or more wireless or hardwired communication links (not shown). Such communication links may include communications via a packet switched network (e.g., the Internet), hardwired telephone lines, cellular communication links and/or other radio frequency based communication links, etc. using any desired communication protocol.

Additionally one or more of the components of the BHA may include one or more processors or processing units (e.g., a microprocessor, an application specific integrated circuit, etc.) to manipulate and/or analyze data collected by the components at a downhole location rather than at the surface.

SUMMARY

In at least one aspect, embodiments relate to a method and an apparatus for communicating between a tool and a surface of a subterranean formation including a signal generator configured to send a signal through the formation, a relay in communication with the generator, and a receiver in communication with the relay. Embodiments also relate to a method and an apparatus for communicating between a tool and a surface of a subterranean formation including sending a signal from a generator configured to send a signal through a formation, receiving the signal at a relay, sending a second signal from the relay, and receiving the second signal at a receiver.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the above recited features and advantages of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof that are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

FIG. 1 (Prior Art) is a schematic view, partially in cross-section, of a measurement while drilling tool and wellbore telemetry device connected to a drill string and deployed from a rig into a wellbore.

FIG. 2 is a plot of data rate as a function of distance to illustrate a capacity of mud pulse under a certain simple model.

FIG. 3 is a schematic of one embodiment of a relay placed along a wellbore in a subterranean formation.

FIG. 4 is a sectional view of a schematic diagram of an embodiment of a formation, wellbore, surface equipment and relay.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of the present disclosure. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments are possible.

The following terms have a specialized meaning in this disclosure. While many are consistent with the meanings that would be attributed to them by a person having ordinary skill in the art, the meanings are also specified here.

In this disclosure, “fluid communication” is intended to mean connected in such a way that a fluid in one of the components may travel to the other. For example, a bypass line may be in fluid communication with a standpipe by connecting the bypass line directly to the standpipe. “Fluid communication” may also include situations where there is another component disposed between the components that are in fluid communication. For example, a valve, a hose or some other piece of equipment used in the production of oil and gas may be disposed between the standpipe and the bypass line. The standpipe and the bypass line may still be in fluid communication so long as fluid may pass from one, through the interposing component or components, to the other.

A “drilling system” typically includes a drill string, a BHA with sensors, and a drill bit located at the bottom of the BHA. Mud that flows to the drilling system must return through the annulus between the drill string and the borehole wall. In the art, a “drilling system” may be known to include the rig, the rotary table and other drilling equipment, but in this disclosure it is intended to refer to those components that come into contact with the drilling fluid.

Embodiments relate to drilling fluid telemetry systems for modulating the pressure of a drilling fluid channel inside the drill pipes to communicate downhole measurement information to the surface without using wire.

As oil wells are drilled deeper, mud pulse telemetry system may face a bigger challenge to enable reliable higher-rate telemetry at larger depths. Several improvements and/or features are desirable, such as:

Larger mud pulse signal amplitude

Larger modulator velocity in order to generate larger mud pulse signal bandwidth

Resistance to jamming, corrosion and wear

The challenge of providing reliable telemetry over long distance is due to large signal decay or path loss, which grows exponentially. Shown in FIG. 2 is the estimated transmission rate vs. depth by using our ADVANCE MUD PULSE TOOL™ (which is commercially available from Schlumberger Technology Corporation of Sugar Land, Tex.). The two curves represent two different data rate responses according to mud attenuation from light attenuate mud shown in blue to heavy attenuate mud shown in black. As the pulse traveling distance increases regardless of mud types we will eventually have to transmit data in single digit rate. Regardless, path loss increases exponentially with distance.

Instead of increasing the pulse amplitude to overcome attenuation, we propose a different approach by implementing a relay at half way between the surface and drill bit in order to transmit data at much higher rate. The relay may be positioned at exactly the midpoint between the surface and bit or it may be positioned elsewhere to optimize the signal transmission. The relay may be used in combination with additional relays and/or repeaters to optimize the transmission.

One configuration is for the BHA to send its telemetry signal at low frequency and for the relay to send its signal at high frequency. A mud pulse signal typically propagates better at low frequencies. Therefore, the relay can be positioned closer to the surface for easier access. Noise due to mud pumps tend to be at lower frequencies. Thus, the relay can send its signal at high frequency in order to increase signal quality that is received at the surface.

The new modulator design also has the advantages of lower power requirement for the same data rate and compact form factor. These help enable the deployment of a repeater or relay to improve the overall performance of the mud pulse telemetry system.

Device and Conveyance

The relay is deployed between the mud pump and drill bit, often half way. It will have to include a receiver to listen to what have been sent up by the first mud pulse modulator near the drill bit. However, this receiver is away from both noise sources at the drill bit and surface mud pump. Intuitively it is easier to decode because the signal strength is very likely to be bigger than the noises. The only interferences will likely come from the forwarding signals at this relay station. Therefore, we ought to have a modulator that is capable of transmitting signals at different frequency band either high or low enough to allow us to isolate the interferences, in addition to a potential physical separation of 90 feet distance between the receiver and transmitter, because a typical rig height can accommodate three 30 feet drill pipes. Multiple receivers can be included depending upon justifying their worthiness. In some embodiments, if longer than 90 feet, receiver separation is necessary, then we can use a few sections of wired drill pipe to link the receiver to the processing and the modulation units.

Looking at the 25,000 ft heavy mud data rate response curve in FIG. 1, if one can deploy a relay at 12,000 ft, we can still transmit signal at higher rate than otherwise. For light mud, we can transmit signals through the distance of 50,000 ft at high rate.

FIG. 3 shows a telemetry system including a relay 301 located on the drill string 302 between the BHA 303 and the surface system 304. The location of the relay 301 can be optimized in order to obtain the best signal decoding from the BHA 303 and the best signal transmission to the surface 304. One way to optimize is to select the distances between equipment. That is, the distance 306 between the BHA 303 and relay 301 and the distance 305 between the relay 301 and surface 304 may be tailored for optimum signal properties. Further, additional relays and/or receivers may be positioned along distances 305 and 306.

A few elements form a relay station. The relay must first receive the uplink signal from the BHA. It can then perform denoising and/or equalization and/or decoding. Then it re-encodes the information and transmits the signal to the surface. Therefore, at the minimum, the relay includes the following functional blocks.

-   -   1. A mud pulse receiver/decoder.     -   2. A power supply or generator. As an example, this can be a         turbine or a battery or a combination of the two.     -   3. A mud pulse transmitter/encoder.

FIG. 4 shows the deployment of a mud pulse module 401 near the bit 404 and a relay station 402 in the middle of drill string 403 with two sensors (not shown) to receive bit information sent up from the modulator 401 near the bit 404. The sensor, which may be a receiver, at the relay 402 can then combine the signal received by the two sensors to improve decoding of the signal. The signals received at the surface 405 may contain pulses coming from the modulator 401 at the bit 404 and the signals sent from the relay station 402. The signals coming from the relay station 402 are likely to be much stronger than the signals coming from the modulator 401 near the bit 404. A receiver (not shown) at surface 405 may be configured to receive both sets of signals and may also be configured to optimize the demodulation. Different arrows 406 along the drill string 403 indicate different carrying frequency, which is one of the possible ways to convey information.

Alternatives are also possible. As a practical matter, the signal may be mud pulse, electromagnet, acoustic or a combination thereof. Further, the position of the module and the surface receiving equipment may be alternated such that the signal is sent from the surface to the BHA. The signal generator and the relay may send signals that are not of the same frequency or type.

Telemetry Methodologies

We now describe the operation of the telemetry components to facilitate efficient operation and performance. Recall that for a fixed signal power, the possible data rate will decrease exponentially with distance.

Here, we focus on the case where both the relay and the BHA wish to send information to the surface. Because the relay itself also has a receiver/processor, it is possible for the relay to also receive information from the BHA.

1. Channel Sharing

The relay has to share the mud pulse channel with the downhole mud pulser at the BHA, because a mud pulser or modulator generates pressure differential to convey information, and the pressure signal propagates both upwards and downwards (with negative polarity). Because of the shared medium, all receivers are affected by all transmitters. Hence, it is important to consider methods for efficiently sharing the channel.

Channel Sharing Strategies:

1. Time-domain division: BHA sends pressure signal at different times than the relay. For example, the BHA sends a signal for some proscribed time. The relay then waits until this signal is fully sent and received at the relay, then sends its uplink signal. The BHA then waits for the relay's signal to be fully sent before it sends its own signal.

2. Frequency-domain division. For example, the BHA sends a signal at low frequency, and the relay sends a signal at high frequency. In this fashion it is possible to distinguish the two signals at the surface, or to decode the relay's signal with minimal interference from the BHA's signal.

3. Code-based division.

4. Combinations of the above.

Format of signal in the relay: It may be desirable to relay not only the decoded bits but also some bit confidence information, to enable better processing or error correcting coding at the surface system. The relay can also add information generated at the relay station, such as status updates.

Performance Estimates

Time domain division performance

For concreteness, suppose that we wish to enable communication from a BHA at 20 kft of depth to the surface. Suppose that we have a relay/repeater at 10 kft. With viscous mud and current modulator technology with signal level at 500 psi peak-to-peak, we can achieve only 4.25 bps at 20 kft. For 10 kft of distance, we can achieve 64 bps. This is because the signal energy loss is exponential with distance, so we more than double the data rate when we halve the distance. Hence, even if we can only use 40% of the duty cycle for each transmitter in the link, we still achieve 26 bps.

Frequency domain division performance

This is advantageous because at low frequencies the propagation of mud pulse is better but there is more pump noise. So it is advantageous to send at low frequency from the BHA to the relay tool, and the relay tool can be located a little closer to the surface and send its transmission at higher carrier frequency.

Code based division performance

It is possible to also use spread spectrum signaling, where we assign different spreading codes to different transmitters. This allows the spectrum of the signals from the BHA and from the relay to overlap in both time and frequency, with some performance degradation.

Combinations

We can also apply combinations of the above techniques.

2. Processing at the Relay and the Surface (Final Destination) Processing of Received Signal at Relay

Upon receiving the signal from the BHA, the relay can do one or a combination of the following:

It can decode the information sent by the BHA. For example the uplink signal from the BHA can be sent at lower frequency in order to have minimal propagation loss, but the relayed signal can be sent at higher frequency in order to mitigate the impact of pump noise at the surface.

It can record a representative waveform of the signal generated by the mud modulator of the BHA, which it receives at the relay tool. The information carried in this waveform may not be fully decoded by the relay tool.

The latter method has the advantage of being able to relay to the final destination at the surface some “soft” information regarding the reliability of the received waveform at the relay.

The relay tool then relays these and optionally additional information, to the surface system, using the channel sharing method(s) described in the previous subsection. It does so at its own preferred modulation format, carrier frequency and data rate.

Relaying of Information

There are several options of what signal to be transmitted by the relay:

1. The relay can decode-and-forward the message from the BHA.

2. The relay can compress-and-forward the message from the BHA. An example of compression is to send only partial information in order to assist the surface system in the decoding of the signal from the BHA as received at the surface. This option allows for lower transmission power at the relay.

3. The relay can amplify-and-forward, thus not requiring full decoding at the relay. This will simplify the relay and minimize the relaying delay.

In order to minimize relaying delay, the relay may begin to transmit its signal before fully decoding the frame or packet from the BHA.

Processing of Received Signal at the Surface (Final Destination)

The surface system receives both the signal from the BHA and also the signal from the relay(s). If the relayed signal is similar, it may use both signal simultaneously to further improve robustness to noise and to reflections in propagation. As an example, the surface system can estimate the transmitted information based on the signal sent by the BHA and the signal sent by the relay. For each atomic unit of information, such as a bit or a set of bits, its reliability and likelihood can be assessed, based on each signal. Then, a combined estimate of the information can be computed that improves upon each individual estimate.

The surface receiver may use array receiver techniques to be able to separate the signal from the BHA and the signal from the relay, or to optimally combine the two signals if they can be used in such a fashion.

There are several options for optimizing the overall system performance. It is known today that pump noise from the surface is a dominant limiting factor, in addition to nulls in the propagation channel due to reflectors from surface piping, pipe ID changes, the BHA/bit, etc. The impact of reflections depends on the frequencies of interest, and on the spatial location of the transmitter, relay, receiver and the reflectors themselves. Therefore, it is advantageous to choose the placement of the relay to mitigate the impact of reflections.

Further it is important to select the appropriate frequency band and transmission rate for the link from the BHA-to-relay and the relay-to-surface. If the surface receiver is at a disadvantage due to the nature of the impairments mentioned above, then one or a combination of the following can be used to improve performance:

1. Locate the relay closer to the surface than to the BHA. This means that the signal from the relay as received at the surface is of larger amplitude, and helps with the signal-to-noise ratio at the surface.

2. Use different data rates in the BHA-to-relay and relay-to-surface links. Then the relay may have to buffer some data, and it may make a decision as to which data set is to be sent to the surface.

3. As the surface receiver also receiver a (weaker) version of the signal sent by the BHA, it may do array processing or multiuser decoding methods to improve the decoding of the overall signal.

Embodiments of a relay station will help us to deliver stronger and higher data rate (the a signal received by the receiver has a higher signal to noise ratio than if no relay were present.) from the BHA to the surface and we can deploy more than one relay station if it is necessary. It may be combined with other means of signal transmission, for example, using wired drill pipes from relay station to the surface as well as a wired sea bottom receiver station to electrically deliver the last section of the transmission to the surface rig by wire.

Finally, a relay station can also be used to improve downlink instead of or in addition to uplink.

This description is intended for purposes of illustration only and should not be construed in a limiting sense. The scope of this invention should be determined only by the language of the claims that follow. The term “comprising” within the claims is intended to mean “including at least” such that the recited listing of elements in a claim are an open group. “A,” “an” and other singular terms are intended to include the plural forms thereof unless specifically excluded. 

What is claimed is:
 1. An apparatus for communicating between a tool and a surface of a subterranean formation, comprising: a signal generator configured to send a signal through the formation; a relay in communication with the generator; and a receiver in communication with the relay.
 2. The apparatus of claim 1, wherein a signal received by the receiver has a higher signal to noise ratio than if no relay were present.
 3. The apparatus of claim 1, wherein the relay and generator are separated by a distance, wherein the relay and receiver are separated by a second distance, and the first and second distance are tailored for signal clarity.
 4. The apparatus of claim 1, wherein the relay is configured to modify the signal it receives before it sends a modified signal to the receiver.
 5. The apparatus of claim 1, wherein the signal is a mud pulse.
 6. The apparatus of claim 1, wherein the signal is electromagnetic.
 7. The apparatus of claim 1, wherein the signal is acoustic.
 8. The apparatus of claim 1, wherein the signal generator is positioned at the surface of the formation.
 9. The apparatus of claim 1, wherein the signal generator is positioned in a wellbore in the formation.
 10. The apparatus of claim 1, wherein the receiver is positioned at the surface of the formation.
 11. The apparatus of claim 1, wherein the receiver is positioned at in a wellbore in the formation.
 12. The apparatus of claim 1, wherein the generator and relay send signals that do not have the same frequency.
 13. The apparatus of claim 1, further comprising an additional relay.
 14. The apparatus of claim 1, further comprising a repeater.
 15. A method for communicating between a tool and a surface of a subterranean formation, comprising: sending a signal from a generator configured to send a signal through a formation; receiving the signal at a relay; sending a second signal from the relay; and receiving the second signal at a receiver.
 16. The method of claim 15, wherein the relay modifies the signal it receives before it sends the second signal to the receiver.
 17. The method of claim 15, wherein the signal and/or second signal is a mud pulse.
 18. The method of claim 15, wherein the signal and/or second signal electromagnetic.
 19. The method of claim 15, wherein the signal is acoustic.
 20. The method of claim 15, wherein the signal generator is positioned at the surface of the formation.
 21. The method of claim 15, wherein the signal generator is positioned in a wellbore in the formation.
 22. The method of claim 15, wherein the generator and relay send signals that do not have the same frequency.
 23. The method of claim 15, wherein the receiver receives the signal and the second signal.
 24. The method of claim 23, wherein the receiver optimizes the demodulation. 